Bitumen based indirect steam boiler

ABSTRACT

Systems and methods generate steam in hydrocarbon recovery operations and may further enable emulsion separation and product upgrading. The methods rely on indirect boiling of water by contact with a thermal transfer liquid heated to a temperature sufficient to vaporize the water. Examples of the liquid include oils, recovered hydrocarbons, liquid metals and brine. Heating of the liquid may utilize circulation of the liquid across or through a furnace, heat exchangers, or a gas-liquid contactor supplied with hot gas. Further, a solvent for bitumen introduced into the water may also vaporize upon contact with the thermal transfer liquid.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a non-provisional application which claims benefit under 35 USC §119(e) to U.S. Provisional Application Ser. No. 61/737,937 filed Dec. 17, 2012, entitled “BITUMEN BASED INDIRECT STEAM BOILER,” which is incorporated herein in its entirety.

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

None.

FIELD OF THE INVENTION

Embodiments of the invention relate generally to methods and systems for use in hydrocarbon recovery operations, such as oil sands production.

BACKGROUND OF THE INVENTION

Several techniques utilized to recover hydrocarbons in the form of bitumen from oil sands rely on generated steam to heat and lower viscosity of the hydrocarbons when the steam is injected into the oil sands. One common approach for this type of recovery includes steam assisted gravity drainage (SAGD). The hydrocarbons once heated become mobile enough for production along with the condensed steam, which is then recovered and recycled.

Costs associated with building a complex, large, sophisticated facility to process water and generate steam contribute to economic challenges of oil sands production operations. Such a facility represents much of the capital costs of these operations. Chemical and energy usage of the facility along with expense of diluents to maintain transportability of the bitumen once cooled also contribute to operating costs.

Past approaches rely on once through steam generators (OTSGs) to produce the steam. However, boiler feed water to these steam generators requires expensive de-oiling and treatment to limit boiler fouling problems. Even with this treatment, fouling issues persist and are primarily dealt with through regular pigging of the boilers. This recurring maintenance further increases operating costs and results in a loss of steam production capacity, which translates to an equivalent reduction in bitumen extraction.

Therefore, a need exists for methods and systems for generating steam and/or product upgrading that enable efficient hydrocarbon recovery operations.

BRIEF SUMMARY OF THE DISCLOSURE

In one embodiment, a method of separating and upgrading liquid hydrocarbons includes introducing into a vessel a mixture recovered from an underground formation and including the hydrocarbons and produced water. The method further includes heating the hydrocarbons in a bottom of the vessel such that the produced water introduced into the vessel is vaporized by contact with the hydrocarbons that are heated and rises to an overhead of the vessel for removal. A sales portion of the hydrocarbons upgrade by visbreaking resulting from the heating and is withdrawn from the vessel.

For one embodiment, a system for separating and upgrading liquid hydrocarbons includes a production well for recovering a mixture of produced water and the hydrocarbons from an underground formation, a vessel coupled to the production well for receiving the mixture and a heater to increase temperature of the hydrocarbons in a bottom of the vessel to above a boiling point of the water and a thermal cracking point of the hydrocarbons. An overhead conduit couples to a top of the vessel for withdrawing steam from vaporization of the water by contact with the hydrocarbons. A liquids conduit couples to the bottom of the vessel for withdrawing a sales portion of the hydrocarbons upgraded by visbreaking

BRIEF DESCRIPTION OF THE DRAWINGS

A more complete understanding of the present invention and benefits thereof may be acquired by referring to the follow description taken in conjunction with the accompanying drawings.

FIG. 1 is a schematic of a system in which produced water is separated from recovered oil and vaporized by contact with a heated liquid to produce steam for injection, according to one embodiment of the invention.

FIG. 2 is a schematic of an alternative arrangement to contact a mixture of water and oil with more of the oil that has been heated to vaporize the water and result in visbreaking of the oil, according to one embodiment of the invention.

FIG. 3 is a schematic of another system utilizing brine heated by coils within a steam generation vessel to vaporize water introduced into the vessel, according to one embodiment of the invention.

FIG. 4 is a schematic of a system employing a gas-liquid contactor to maintain temperature of a heated liquid used to generate steam, according to one embodiment of the invention.

FIG. 5 is a schematic of a system having a condensable gas circulated through a gas-liquid contactor employed to maintain temperature of a heated liquid used to generate steam, according to one embodiment of the invention.

DETAILED DESCRIPTION

Turning now to the detailed description of the preferred arrangement or arrangements of the present invention, it should be understood that the inventive features and concepts may be manifested in other arrangements and that the scope of the invention is not limited to the embodiments described or illustrated. The scope of the invention is intended only to be limited by the scope of the claims that follow.

Embodiments of the invention relate to systems and methods of generating steam in hydrocarbon recovery operations and that may further enable emulsion separation and product upgrading. The methods rely on indirect boiling of water by contact with a thermal transfer liquid heated to a temperature sufficient to vaporize the water. Examples of the liquid include brine, liquid metals and petroleum based fluids, such as oils, bitumen or recovered hydrocarbons. Heating of the liquid may utilize circulation of the liquid across or through a furnace, heat exchangers, or a gas-liquid contactor supplied with hot gas. Further, a solvent for bitumen introduced into the water may also vaporize upon contact with the thermal transfer liquid.

FIG. 1 shows a steam generator vessel 100 for use in a steam-assisted hydrocarbon recovery operation, which may utilize an injection well 101 and a production well 102 in an underground formation. Steam-assisted gravity drainage (SAGD) provides one exemplary approach for recovering hydrocarbons even though steam generation described herein may be used in other processes, such as cyclic steam stimulation or steam flood. For the SAGD, the injection well 101 includes a horizontal length extending parallel and above the production well 102.

In operation, the production well 102 recovers an emulsion or mixture 104 of hydrocarbons and produced water. A separator 106 and free-water knockout units 108 remove hydrocarbon product 110 from untreated water 112. The water 112 at time of being generated into the steam may still contain: at least about 1000 parts per million (ppm), at least 10,000 ppm or at least 45,000 ppm total dissolved solids; at least 100 ppm, at least 500 ppm, at least 1000 ppm or at least 15,000 ppm organic compounds or organics; and at least 1000 ppm free oil, thereby enabling sustainable recycle of the water 112 without stringent treatment requirements of conventional boiler feed.

For some embodiments, the water 112 mixes with a solvent 114 for bitumen prior to vaporization in the vessel 100. The solvent 114 thus may flow in liquid phase into the water 112. Vaporization of the water 112 along with the solvent 114 within the vessel 100 results in solvent vapors also being introduced into the injection well 101 as may be desired in some recovery operations.

The solvent 114 may include hydrocarbons having between 3 and 30 carbon atoms, such as butane, pentane, naphtha and diesel. Temperatures associated with the indirect boiling described herein limit potential problems from cracking these hydrocarbons, which can tend to occur if passed through direct fired boilers that may thus require injection of any wanted solvents into superheated steam rather than boiler feed. Feed to the vessel 100 may include between 5 and 30 percent of the solvent 114 by volume.

The solvent 114 may further provide an energy requirement for vaporization that is at least 10 percent lower than water alone. For example, a 28:72 ratio of butane to water reduces steam generator duty using the vessel 100 by 24 percent as compared to water alone. Further, vaporization of the solvent 114 in the vessel 100 eliminates need for superheated steam generation relied on when the solvent 114 is added post steam generation.

A pump 116 pressurizes the water 112 for entry into the vessel 100 maintained at a pressure of at least 10,000 kilopascals to achieve a corresponding desired steam injection pressure. In some embodiments, the pump 116 pressurizing the water 112 to above 13,500 kilopascals before the water 112 enters the vessel 100 at a temperature below its boiling point at such pressure. A nozzle 118 or other dispersion inlet may introduce the water 112 into the vessel 100 as droplets or dispersed flow to aid in heat transfer between the water 112 and a thermal transfer liquid 120, which vaporizes the water 112. The nozzle 118 may direct the water 112 toward the liquid 120 or be disposed within the liquid 120 as shown in other figures.

Any fluid having a boiling point above the water 112 may form the liquid 120, which may also not be miscible with the water 112. Examples of the liquid 120 include liquid metals, brine and hydrocarbons, such as bitumen, light cycle oil, heavy cycle oil, coker gas oil or aromatics. Using hydrocarbons that have already been cracked as the liquid 120 may limit loss and fouling from potential further cracking when the liquid 120 is intended to be recycled within the vessel 100 whereas use of bitumen as the liquid 120 may provide potential for withdrawal of upgraded products.

In some embodiments, a circulation loop 122 through which the liquid 120 from the bottom of the vessel 100 is pumped reheats the liquid 120 cooled by heat transfer to the water 120. A heater 124 such as a furnace, heat exchanger, or gas-liquid contactor supplied with a hot gas increases temperature of the liquid 120. In some embodiments, the heater 124 increases temperature of the liquid 120 to above 350° C., 400° C., 425° C. or 475° C. before being returned to the vessel 100 thereby maintaining temperature of the liquid 120 within the vessel 100 above a boiling point of the water (e.g., 315° C.).

Circulation rate depends on an energy balance around duty required to vaporize the water 112 and temperature difference between the liquid 120 entering and exiting the vessel 100. Increasing temperature of the liquid 120 decreases required circulation rates for the liquid 120 but may be limited by thermal stability or coking of the liquid 120. Mean residence time of the liquid 120 in the vessel 100 provides sufficient thermal capacity to dampen perturbations in feed rate of the water 112 or circulation rate or temperature of the liquid 120.

The circulation loop 122 may further include a purge 126 and a makeup inlet 128 for replacing any of the liquid 120 purged with fresh supply. This purging and replacement of the liquid 120 prevents problems from buildup of contaminants resulting from the heating or transferred to the liquid 120 during vaporization of the water 112. Organic contaminants in the water 112 may remain with the liquid 120 also such that one benefit of utilizing the hydrocarbons for the liquid 120 is that these organics can form part of the liquid 120 without requiring any treatment. Filters disposed along the circulation loop 122 may also help keep the liquid 120 clean by solids removal of inorganic material deposited by the water 112.

With the liquid 120 heated, contact of the water 112 with the liquid 120 within the vessel 100 thus results in vaporization of the water 112 into steam 130 output from an overhead of the vessel 100. The steam 130 rises in the vessel for separation from the liquid 120 and is then conveyed to the injection well 101 for introduction into the formation. In some embodiments, a fractionation column provides the vessel 100 to facilitate separation and enable pulling off separate streams for the steam 130 and any light hydrocarbons if not desired for passing through to the injection well 101.

For some embodiments, separation of the water 112 from the hydrocarbon products 110 occurs at a central processing facility 132 separate and remote (e.g., at least 100 meters or 1 kilometer) from a well pad 134 where the vessel 100 is disposed. Producing steam at the pad 134 (i.e., less than 100 meters from the injection well 101) instead of the central processing facility 132 enables the steam pressure to be lower (e.g., between 5000 and 10,000 kilopascals) and therefore the steam temperature to be lower as well (e.g., between 260° C. and 350° C.). These parameter requirement changes in turn allow the liquid 120 with relative higher differential temperature to transfer more sensible heat per pound of liquid 120 if at the pad 134 than at the central processing facility 132.

Placement of the vessel 100 at the pad 134 therefore enables decreasing circulation rate needed for the liquid 120. The injection of the solvent 114 further lowers the circulation rate required for the liquid 120. By way of example, location of the vessel 100 at the pad 134 along with the solvent 114 use may lower the circulation rate by 60% compared to vaporizing the water 112 alone at the central processing facility 132 (i.e., a reduction in liquid 120 to steam 130 ratio from 10:1 to 4:1).

FIG. 2 illustrates a bitumen based system with a steam generator vessel 200, an injection well 201 and a production well 202 that are operated for steam generation without first separating a mixture 204 of water and hydrocarbons from the production well 202. A feed pump 216 pressurizes the mixture 204 that is then preheated in a furnace or heat exchanger 217 prior to introduction into the vessel 200. In some embodiments, the mixture 204 may receive heat from a sales portion 210 of the hydrocarbons.

Upon entry into the vessel 200, some flashing of the water in the mixture 204 may occur upon expansion into relative lower pressure conditions of the vessel 200. Remaining water in the mixture 204 vaporizes upon contact with hot bitumen 220 collected in a bottom of the vessel 200 and formed of the hydrocarbons in the mixture 204 that are heated in a circulation loop 222. The circulation loop 222 contains a recycle pump 221 that passes the bitumen 220 from the vessel 200 to a desalter 223 and then a furnace 224 before returning the bitumen 220 to the vessel 200.

The desalter 223 removes inorganic material from the bitumen 220. Some of the bitumen 220 exiting the desalter 223 provides the sales portion 210 of the hydrocarbons for pipeline or transport to a refinery for further processing. The furnace 224 heats a remainder of the bitumen 220 from the desalter 223 to a temperature above a boiling point of the water at the pressure conditions in the vessel 200.

For some embodiments, overhead from the vessel 200 passes through a separation device 229 that may include demisters, separators, fractionators and/or particulate filters. The device 229 removes entrained liquids and/or solids 233 and/or condensable hydrocarbons 231 vaporized by the bitumen 220 or resulting from cracking of the bitumen 220. The condensable hydrocarbons 231 may mix back into the sales portion 210 of the hydrocarbons or have a portion mixed back for injection into the formation as a solvent.

Steam 230 exits the device 229 and is conveyed to the injection well 201. Some embodiments may introduce steam in the furnace 224 to mitigate fouling or superheat and inject steam in the bottom of the vessel 200 to facilitate vaporization of the water. Since separation of the mixture 204 occurs with the vessel 200, this approach eliminates need for independent de-oiling equipment.

Residence time of the bitumen 220 in the vessel 200 provides sufficient soak time for visbreaking of the bitumen 220. Exemplary soaking times may range from 5 minutes to 1 hour with the bitumen heated in the furnace 224 to at least 385° C. The circulation loop 222 may incorporate various approaches to enhance the visbreaking, such as radiation thermal cracking or hydrodynamic cavitation. The visbreaking lowers viscosity and density of the bitumen 220 and hence the sales portion 210 making the sales portion 210 more valuable and easier to transport while requiring less diluents than the bitumen without such upgrading.

FIG. 3 shows a brine based system utilizing a steam generator vessel 300, an injection well 301 and a production well 302 similar to other embodiments. In operation, a mixture 304 from the production well 302 flows to a separator 306 that divides the mixture 304 into separate streams of hydrocarbons 310 and water 312. A feed pump 316 supplies the water 312 at desired pressure into the vessel 300.

The vessel 300 contains a pool of brine 320 heated to a temperature above a boiling point of the water 312 introduced into the vessel 300. In some embodiments, an aqueous solution of sodium chloride forms the brine 320 that may have at least 50 grams of salt per liter of water. Such salt concentrations thus exceed amount of salt present in the water 312 input into the vessel 300 for vaporization.

For some embodiments, heating of the brine 320 may occur by heat transfer with another fluid such as hot gas or liquids. For example, an exchanger circuit pump 321 may circulate molten sodium through a furnace 324 to reheat the sodium that is then passed through heating coils 325 immersed in the brine 320 disposed in the vessel 300. The furnace 324 heats the sodium to a temperature, such as above 500° C., selected above an operating temperature in the vessel 300 such that heat transfers from the sodium through walls of the coils 325 to the brine 320 and leaves the coils 325 at a lower temperature to be reheated.

Similar to other steam generation techniques described herein, the water 312 vaporizes upon contacting the brine 320 with resulting steam 330 that rises in the vessel 300 being withdrawn and conveyed to the injection well 301. Organic impurities within the water 312 may partition between the steam 330 and the brine 320. Any volatile organics that pass through with the steam 330 may flow to the injection well 301 and act as solvent in recovery of the hydrocarbons.

Inorganic and nonvolatile organic contaminates in the water 312 remain in the brine 320 once the water 312 vaporizes. The brine 320 may remain in constant agitation by mixers or recirculation, such as provided with a brine pump 350. This agitation prevents the brine 320 from fouling on the coils 325, inlets for the water 312 or walls of the vessel 300. While part of the brine 320 output by the brine pump 350 returns to the vessel 300, a portion of the output from the brine pump 350 goes for further treatment thereby protecting the pool of brine 320 in the vessel 300 from excessive buildup of the contaminates.

In some embodiments, this further treatment of purged brine includes an optional additional steam recovery unit incorporating (as depicted with a dashed box) a booster pump 352, a brine heater 354 and an auxiliary steam generator 356. Such additional steam generation boosts a water recycle rate associated with the hydrocarbon recovery operation and may facilitate reaching regulated water recycle levels. The booster pump 352 raises pressure of the brine to above an operating pressure of the vessel 300 and hence output pressure of the steam 330. The brine heater 354 then raises temperature of a pressurized output from the booster pump 352 to still be at a temperature, such as at least 365° C., below a boiling point of the brine at this pressure, such as at least 20,000 kilopascals. Fluid flow output from the brine heater 354 enters the steam generator 356 where flashed to produce steam at a pressure at least as high as the steam 330 from the vessel 300 for combination therewith.

Liquids remaining in the steam generator 356 from incomplete flashing into the steam pass to a flash drum 358 for flashing at a lower pressure than the steam 330 from the vessel 300. A vapor overhead 359 from the flash drum 358 thus contains steam of relative lower pressure, such as less than 500 kilopascals, for reuse in applications such as process heating and/or condensing and recycling to mix back with the water 312. If not otherwise disposed, liquids remaining in the flash drum 358 from incomplete flashing into the overhead 359 may pass to a thermal oxidizer 360. Effluents from the oxidizer 360 include flue gas 362 including products from combustion of the organic contaminates in the water 312 that partitioned to the brine 320 and solids 364 suitable for landfill disposal.

FIG. 4 illustrates another system also employing a steam generator vessel 400, an injection well 401 and a production well 402 with further indirect heating used to maintain temperature in the vessel 400. In operation, a mixture 404 from the production well 402 flows to a separator 406 that divides the mixture 404 into separate streams of hydrocarbons 410 and water 412. A feed pump 416 pressurizes the water 412 supplied into the vessel 400 where the water 412 contacts a heated thermal transfer liquid 420 to generate steam 430 conveyed to the injection well 401.

A recycle pump 421 circulates the liquid 420 through a circulation loop 422 where the liquid 420 is reheated to sustain the steam generation. The liquid 420 in the circulation loop 422 passes through a gas-liquid contactor 424 to achieve this reheating before return of the liquid 420 back to the vessel 400. The gas-liquid contactor 424 may avoid problems such as fouling on heater tubes that may occur depending on fluid selected as the liquid 420. For example, use of bitumen or other heavy hydrocarbons as the liquid 420 may result in coking if heated in a furnace.

A thermal transfer gas passes through the gas-liquid contactor 424 along a gas loop 475 and may include hydrocarbon gas, such as methane or butane, nitrogen or argon. A heat exchanger 476 may provide initial heat transfer from the gas loop 475 to the liquid 420 before further heating of the gas in a furnace 478. Once heated, the gas rises through the gas-liquid contactor 424 and contacts the liquid 420 to transfer heat to the liquid 420. In addition to a compressor 480 to supply the gas to the gas-liquid contactor 424, the circulation loop 475 may further include a purge to allow for removal of accumulated water that carries over and a makeup inlet for replacement of this purged gas. A purifier 492 removes any carryover of the gas into the liquid 420 within the circulation loop 422 and that exits the gas-liquid contactor 424 and is pressurized by a booster pump 494 for reentry into the vessel 400.

FIG. 5 shows yet another system also employing a steam generator vessel 500, an injection well 501 and a production well 502 with an alternative indirect heating approach used to maintain temperature in the vessel 500. As with other operations described herein, a mixture 504 from the production well 502 flows to a separator 506 that divides the mixture 504 into separate streams of hydrocarbons 510 and water 512. A feed pump 516 pressurizes the water 512 supplied into the vessel 500 where the water 512 contacts a heated thermal transfer liquid 520 to generate steam 530 conveyed to the injection well 501.

Still like the system in FIG. 4, a first recycle pump 521 circulates the liquid 520 through a circulation loop 522 where the liquid 520 is reheated by a thermal transfer gas in a gas loop 575 to sustain the steam generation. A furnace 578 keeps the gas hot that is sent to a gas-liquid contactor 524. The liquid 520 in the circulation loop 522 passes through a heat exchanger 576 and the gas-liquid contactor 524 to achieve this reheating before return of the liquid 520 back to the vessel 500.

After contact with the liquid 520 in the gas-liquid contactor 524, a first heat exchanger or chiller 582 further cools the gas such that water is removed in a first purifier 584. A second chiller 586 then condenses the gas into a liquid phase for removal of hydrocarbons lighter than the gas in a second purifier 590 and pressurizing in a pump 580 for re-vaporization into the gas in the furnace 578 in order to resupply the gas to the gas-liquid contactor 524. A third purifier 592 removes any carryover of the gas into the liquid 520 within the circulation loop 522 and that exits the gas-liquid contactor 524. A second recycle pump 594 then pressurizes the liquid 520 for reentry into the vessel 500.

Features shown in only one figure, like the nozzle 118 or injection of the solvent in FIG. 1, and described once for succinctness may nevertheless be incorporated with any steam generator vessels described herein and illustrated in other figures. For example, filtering and separating steam output from any of the vessels may occur before injection. While shown in an embodiment with the brine as the thermal transfer liquid, heating coils within any of the vessels may provide for reheating of any other thermal transfer liquid.

In closing, it should be noted that the discussion of any reference is not an admission that it is prior art to the present invention, especially any reference that may have a publication date after the priority date of this application. At the same time, each and every claim below is hereby incorporated into this detailed description or specification as additional embodiments of the present invention.

Although the systems and processes described herein have been described in detail, it should be understood that various changes, substitutions, and alterations can be made without departing from the spirit and scope of the invention as defined by the following claims. Those skilled in the art may be able to study the preferred embodiments and identify other ways to practice the invention that are not exactly as described herein. It is the intent of the inventors that variations and equivalents of the invention are within the scope of the claims while the description, abstract and drawings are not to be used to limit the scope of the invention. The invention is specifically intended to be as broad as the claims below and their equivalents. 

1. A method of separating and upgrading liquid hydrocarbons, comprising: introducing into a vessel a mixture recovered from an underground formation and including the hydrocarbons and produced water; heating the hydrocarbons in a bottom of the vessel such that the produced water introduced into the vessel is vaporized by contact with the hydrocarbons that are heated and rises to an overhead of the vessel for removal; and withdrawing from the vessel a sales portion of the hydrocarbons that have been upgraded by visbreaking resulting from the heating.
 2. The method according to claim 1, further comprising desalting the hydrocarbons withdrawn from the vessel.
 3. The method according to claim 1, wherein the heating of the hydrocarbons occurs in a circulation loop from the vessel.
 4. The method according to claim 1, wherein the mixture is introduced into the vessel through a nozzle as droplets.
 5. The method according to claim 1, further comprising preheating the mixture prior to being introduced into the vessel.
 6. The method according to claim 1, further comprising preheating the mixture by heat exchange with the sales portion of the hydrocarbons prior to the mixture being introduced into the vessel.
 7. The method according to claim 1, further comprising injecting steam removed from the overhead of the vessel into the formation for additional hydrocarbon recovery.
 8. The method according to claim 1, further comprising removing solids entrained in the steam.
 9. The method according to claim 1, further comprising separating the steam from condensable hydrocarbon gases.
 10. The method according to claim 1, further comprising separating the steam from condensable hydrocarbon gases that are mixed back with the sales portion of the hydrocarbons.
 11. The method according to claim 1, wherein the hydrocarbons are heated to at least 385° C. with residence soak time in the vessel of between 5 minutes and 60 minutes for the visbreaking
 12. The method according to claim 1, wherein the mixture is an emulsion from a steam assisted gravity drainage operation.
 13. A system for separating and upgrading liquid hydrocarbons, comprising: a production well for recovering a mixture of produced water and the hydrocarbons from an underground formation; a vessel coupled to the production well for receiving the mixture; a heater to increase temperature of the hydrocarbons in a bottom of the vessel to above a boiling point of the water and a thermal cracking point of the hydrocarbons; an overhead conduit coupled to a top of the vessel for withdrawing steam from vaporization of the water by contact with the hydrocarbons; and a liquids conduit coupled to the bottom of the vessel for withdrawing a sales portion of the hydrocarbons upgraded by visbreaking
 14. The system according to claim 13, further comprising a desalter disposed along the liquids conduit for desalting the hydrocarbons withdrawn from the vessel.
 15. The system according to claim 13, further comprising a circulation loop from the vessel for heating the hydrocarbons by the heater before being returned to the vessel.
 16. The system according to claim 13, further comprising a nozzle to introduce the mixture as droplets into the vessel.
 17. The system according to claim 13, further comprising a heat exchanger to transfer heat from the sales portion of the hydrocarbons to the mixture prior to the mixture being introduced into the vessel.
 18. The system according to claim 13, further comprising an injection well coupled to the overhead conduit for conveying the steam into the formation.
 19. The system according to claim 13, further comprising a separator to remove solids entrained in the steam.
 20. The system according to claim 13, further comprising a separator to remove condensable hydrocarbons from the steam. 